When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. The fluid often is aqueous. For the purposes herein, such fluid will be referred to as “well fluid.” Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, implacing a packer fluid, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation. Brines (such as CaBr2) commonly are used as well fluids because of their wide density range and the fact that brines are typically substantially free of suspended solids. Additionally, brines typically do not damage certain types of downhole formations.
When drilling progresses to the level of penetrating a hydrocarbon bearing formation, special care may be required to maintain the stability of the wellbore. Examples of formations in which problems often arise are highly permeable and/or poorly consolidated formations. In these types of formations, a technique known as “under-reaming” may be employed.
In this process, the wellbore is drilled to penetrate the hydrocarbon bearing zone using conventional techniques. A casing generally is set in the wellbore to a point just above the hydrocarbon bearing zone. The hydrocarbon bearing zone then may be re-drilled, for example, using an expandable under-reamer that increases the diameter of the wellbore. Under-reaming usually is performed using special “clean” drilling fluids. Typical drilling fluids used in under-reaming are expensive, aqueous, dense brines that are viscosified with a gelling and/or cross-linked polymer to aid in the removal of formation cuttings. The high permeability of the target formation, however, may allow large quantities of the drilling fluid to be lost into the formation.
Once the drilling fluid is lost into the formation, it becomes difficult to remove. Calcium and zinc-bromide brines can form highly stable, acid insoluble compounds when reacted with the formation or substances contained therein. This reaction may reduce the permeability of the formation to any subsequent out-flow of the targeted hydrocarbons. The most effective way to prevent such damage to the formation is to limit fluid loss into the formation.
Thus, providing effective fluid loss control is highly desirable to prevent damaging the formation in, for example, completion, drilling, drill-in, displacement, hydraulic fracturing, work-over, packer fluid implacement or maintenance, well treating, or testing operations. Techniques that have been developed to control fluid loss include the use of fluid loss “pills.” Significant research has been directed to determining suitable materials for the fluid loss pills, as well as controlling and improving the properties of the fluid loss pills. Typically, fluid loss pills work by enhancing filter-cake buildup on the face of the formation to inhibit fluid flow into the formation from the wellbore.
U.S. Pat. No. 6,300,286 (the '286 patent) and the related U.S. Pat. No. 6,576,597 (the '597 patent) describe clay-free well drilling and servicing fluids comprising an aqueous brine which contains at least 0.6 equivalents per liter (the '286 patent) or at least 1.2 equivalents per liter (the '597 patent) of a water soluble divalent cation salt, a particulate bridging agent which is insoluble in the aqueous brine, and a starch derivative which functions as a combination suspending agent and fluid loss control agent. The starch derivative is used in a concentration sufficient to provide the fluid with the following characteristics: (a) a low shear rate viscosity less than about 10,000 centipoise; (b) a high shear rate viscosity at 511 sec−1 in the range from about 15 to about 70 centipoise measured at 120° F.; (c) a fluid loss less than about 10 milliliters as measured at 185° F. and 250 psi differential pressure across a 5 micron disk for 30 minutes; and (d) anti-settling characteristics as exhibited upon static aging the fluid for 16 hours at 185° F. The patents further provides that the low shear rate viscosity can be increased without raising the high shear rate viscosity above about 70 centipoise by incorporating magnesium oxide and/or dipotassium hydrogen phosphate in the fluids.
The '286 patent further discloses that useful brines in the compositions and processes of the '286 patent contain at least 0.6 equivalents per liter of one or more water soluble divalent cation salts. Similarly the '597 patent discloses that useful brines in the compositions and processes of the '597 patent contain at least 1.2 equivalents per liter of one or more water soluble divalent cation salts. Preferred divalent cations are the alkaline earth metal salts and/or zinc salts. The preferred anion is a halide, most preferably chloride and/or bromide. Most preferred divalent cations are selected from the group consisting of calcium, magnesium, zinc, and mixtures thereof. The most preferred salts are selected from the group consisting of calcium chloride, calcium bromide, magnesium chloride, magnesium bromide, zinc chloride, zinc bromide and mixtures thereof. Further, the '286 patent notes that other water soluble salts must be present in the brine at a concentration no less than 0.6 equivalents per liter. Further the '597 patent specifically teaches that other water soluble salts may be present in the brine so long as they do not dilute the divalent cation concentration below about 1.2 equivalents per liter. Thus one of skill in the art would appreciate that a divalent cation is a required element in the inventions disclosed in the above references.
Because of a number of factors including environmental factors, compatibility factors, costs, etc. . . . , the use of divalent cations as disclosed above is not desireable. Thus, what is still needed are fluids which exhibit enhanced particulate suspension characteristics at lower viscosities and which are easier and more completely removed from wellbores, screens, and the like present in hydrocarbon-containing formations.